Deep sea oil production is generally performed from a floating support anchored close to oil wells situated in the sea bottom, i.e. at depths lying in the range 1000 meters (m) to 2500 m, or even more. The floating support generally comprises anchor means enabling it to remain in position in spite of the effects of currents, winds, and swell. It also generally includes means for storing and treating oil together with means for off-loading to off-loading tankers, which tankers call at regular intervals in order to off-load the production. These floating supports are commonly referred to as floating production storage off-loading (FPSO) units, with the acronym FPSO being used throughout the description below.
The well heads are generally connected to said FPSO by undersea pipes that are either of the steel catenary riser (SCR) type, or else of the hybrid tower type, comprising:                a vertical riser having its bottom end anchored to the sea bottom and connected to a said pipe resting on the sea bottom, and its top end tensioned by a float immersed in the subsurface, to which float the top end is connected; and        a connection pipe, generally a flexible connection pipe or “hose” between the top end of said riser and a floating support on the surface, said connection hose possibly presenting, under the effect of its own weight, a shape in the form of a dipping catenary, i.e. it dips well below the float before subsequently rising to said floating support.        
The entire crude oil production is thus generally raised to the FPSO, where it is treated in order to separate the oil proper from the water, the gas, and any sandy components. Once separated, the oil is stored on board, the gas is washed and then delivered to the gas turbines in order to produce the electricity and heat required on board, with any surplus gas being reinjected into the oilfield reservoir in order to raise the pressure in said reservoir. After being freed of any sand in suspension, the water is finally either dumped in the sea after thorough extraction of all particles of oil, or else it is likewise reinjected into the reservoir, with additional sea water taken from the subsurface generally being added in order to achieve the flow rate required for injecting water into the reservoir. The extracted sand, comprising quantities that are minimal in terms of weight, is finally washed and then dumped into the sea.
One method of separating the water and the oil contained in a crude oil that is commonly used on stationary installations on land consists in using tanks of very large volume, generally in the form of elongate cylinders, with the crude oil entering at one end and traveling along a said tank for a duration of about 5 minutes (min) to 10 min, which is long enough for the various phases to separate naturally under gravity by the time they reach the other end. That type of separator is referred to below as a “gravity” separator, and it is generally used for crude oil that also contains gas, with the gas then being recovered from the top portion of the tank, the water and the sand from the bottom portion, and the oil from an intermediate portion. A very wide variety of separators of this type are in existence, and in general they incorporate additional internal devices such as horizontal, vertical, or sloping screens, for the purposes of facilitating separation of the phases and of preventing them from re-mixing at a later stage.
Those separators operate at low pressure, e.g. a pressure lying in the range 3 bars to 10 bars, and sometimes even at less than atmosphere pressure, in order to optimize the degassing of the crude oil. A separator of that type may have a diameter lying in the range 3 m to 4 m and a length lying in the range 15 m to 20 m. This comes from the fact that the transit time must be long enough for the particles of oil situated in the low portion of the separator to have time to rise towards the oil layer situated in the high portion, and similarly for the particles of water situated in the high portion of the separator to have time to move down into the layer of water situated in the low portion of said separator. Thus, the vertical travel time of a particle is very long because of the height of the tank, i.e. because of the diameter of said separator.
In the development of oilfields and after they have been in operation for a few years, it often happens that multiple small discoveries of oil situated in a range of 15 kilometers (km) to 30 km from said FPSO do not in themselves justify installing a new FPSO, and as a result it is desirable to redirect the production from those new wells to an existing FPSO. However, on board said FPSO, the equipment for treating oil is generally being used to full capacity, i.e. at 80% to 90% capacity, and is therefore not capable of treating all of the additional oil coming from remote satellite wells. However, there is enough treatment capacity for such connection providing some of the treatment is performed close to the satellite wells and only pre-treated oil is sent to the surface on board the FPSO for additional treatment prior to being off-loaded. The desired pre-treatment is firstly partial degassing of the crude, with the gas then being reinjected directly in situ into specific wells, followed by water-oil separation, with the water then being treated in specific separators such as cyclones, e.g. a cyclone device as described in patent EP 1 951 434 in the name of the Applicant, in order to reach a level of purity, i.e. an absence of particles of oil, that make it possible either to reinject the oil into a specific local well in order to maintain pressure in the oil reservoir, or else to reinject it directly into the sea. By proceeding in this way, the oil that is sent to the FPSO on the surface has only a remainder of gas and a remainder of water that said FPSO is in a position to treat under good conditions.
It is therefore advantageous to provide liquid/liquid separation devices that are installed on the sea bottom so as to raise to the surface only the oil phase and not the aqueous phase, which may be reinjected into another well at the sea bottom.
If it is desired to install the above-described type of horizontal liquid/liquid gravity separator at the sea bottom, the tank must be capable of withstanding implosion under the effect of the pressure which is substantially 100 bars, i.e. substantially 100 megapascals (MPa), per 1000 m of water depth. Thus, transposing a tank of such a diameter for use at great or very great depth requires wall thicknesses of the order of 100 millimeters (mm) to 250 mm in order to withstand implosion, and such boiler work elements would be very difficult and very expensive to make and install on the sea bottom at great depth.
However, reducing the diameter and the wall thickness of the separator to diameters and thicknesses that are standard for standard undersea pipes would require its length to be increased in order to be capable of separating a sufficient quantity of fluid within the separator. Nevertheless, it is not possible to use separation pipes of excessive length, since there is a danger of creating head loss differentials between the oil and aqueous phases of the crude oil, and that could lead to disturbances to the operation of the separator.
In WO 2007/054651 in the name of the Applicant, a liquid/liquid separation device is described that is suitable for installing on the sea bottom, that device being of the “cyclone” type, making use of centrifugal force, in contrast to the above-described gravity horizontal separators that make use of the force of gravity for performing separation. However implementing cyclone type separators on the sea bottom is difficult because they present an operating point that can accommodate little variation in the water/oil and the liquid/solid ratios.
The term “operating point” is used herein to mean a point at which volumes of different-density phases can be separated in stable manner within the cyclone.
Unfortunately, another major problem in any oilfield development comes from the fact that over the lifetime of an oilfield, the volume of gas relative to a cubic meter (m3) of crude oil (“gas-oil ratio” or GOR) and also the percentage of water (“water cut”) varies to a very considerable extent and rarely in predictable manner over the period of 20 years to 30 years, or longer, that the separators are in use. In general, the water cut increases up to about 80% to 90% or even more, and it is practically impossible to connect such a well directly to an FPSO that is already at its capacity limit, and such a connection would in general not be profitable.
A problem on which the present invention is based is thus providing a liquid/liquid separator that makes it possible firstly to treat increasing quantities of crude oil over the lifetime of the installation, i.e., as appropriate, oil from additional wells, and secondly to treat crude in which the variations over time in the flow rate of the crude leaving the well and/or the variations of the proportion of water within the crude for treating make it necessary to be able to redefine the operating parameters of the separator and/or to modify the actual structure of the separator during its lifetime in terms of length, of diameter, and of the flow rate of fluid traveling therethrough.